Systems and methods for monitoring and controlling tank pressure and related componentry

ABSTRACT

The SpindleIO tank pressure control systems and methods optimize well production with an algorithm that incorporates tank system pressure, sales line pressure, well tubing pressure and well casing pressure. The algorithm constantly monitors all operating pressures simultaneously to meet various regulatory and compliance thresholds, while also optimizing well output production.

CROSS-REFERENCE TO RELATED APPLICATION

This application claims the benefit under 35 U.S.C. § 119(e) of U.S. Provisional Patent Application No. 62/963,997 filed on Jan. 21, 2020, which is hereby incorporated herein by reference for all that it discloses.

TECHNICAL FIELD

The present disclosure relates to systems and methods for monitoring well tank pressures, and more particularly to automated systems and methods for maximizing well production by continuously monitoring a plurality of pressures within the well tank system.

BACKGROUND OF THE INVENTION

Those of skilled in the art of oil and gas production will appreciate that that federal, state, and local environmental protection agencies have increasingly promulgated rules related to gas/oil holding tank emissions. Violations of these rules, which often rely on overly-tight tolerances, expose companies to steep fines and/or penalties. Accordingly, it is desirable to provide systems that control holding tank, line, and/or casing pressures to minimize gaseous discharge while optimizing well production.

The rules mentioned above can take the form of an EPA consent decree. The following terms common in consent decrees should assist in the understanding of the following disclosure:

Dump Event: Separator, or other pressurized vessel, releasing pressurized liquids to the Tank System.

Leak Point: The lowest pressure at which emissions are released from any pressure relief devices on a Tank System. The value of the Leak Point will not be a value exceeding the Set Point.

Low Pressure Point: Low pressure in the Tank System in a Closed Loop Vapor Control System at which the control logic is set to alarm. The Low Pressure Point is established to identify the potential for failed pressure monitors.

Lower Control Point: The designated pressure at which the Closed Loop Vapor Control System control logic takes action to resume well production flow into the Separator and/or Tank System.

Set Point: The rated pressure at which the tank pressure relief device is designed to open or relieve. The Set Point shall be less than or equal to the manufacturer's rated pressure of the associated Condensate tank(s).

Static Alarm: Alarm that indicates failed pressure monitor(s). The Static Alarm is triggered when pressure readings remain constant for a predetermined duration. Well Production Operations shall be shut-in in response to a Static Alarm.

Tank System: one or more atmospheric storage tanks that store Condensate, and any other interconnected tank (e.g., produced water tank), and that share a common Vapor Control System.

Tank System Operations: Transfer of Condensate from the Separator to the Tank System.

Trigger Point: Selected tank pressure below the Leak Point and above the Upper Control Point at which the Closed Loop Vapor Control System control logic triggers an alarm, and at which Well Production Operations and/or Tank System Operations are automatically Shut-In.

Upper Control Point: The designated pressure at which the Closed Loop Vapor Control System control logic takes action to cease well production flow to the Separator or outflow from the Separator to the Tank System.

Vapor Control System: System used to contain, convey, and control vapors from one or more Condensate tank(s) (including flashing, working, and standing losses, as well as any natural gas carry-through to Condensate tanks). A Vapor Control System includes a Tank System, piping to convey vapors from a Tank System to a combustion device and/or vapor recovery unit, fittings, connectors, liquid knockout vessels or vapor control piping, openings on tanks (such as PRDs, PRVs and thief hatches), and emission control devices.

Well Modulation: The act of controlling production flow into a Separator during a well production cycle.

Well Production Operations: Surface operations to produce Condensate and/or natural gas from any well associated with a Tank System, but shall not include well maintenance activities (e.g., swabbing).

SUMMARY OF THE INVENTION

The tank pressure control system of one embodiment of the present invention, which may also be referred to herein as “SpindleIO,” optimizes well production with an algorithm that incorporates tank system pressure, sales line pressure, well tubing pressure and well casing pressure. The algorithm constantly monitors all operating pressures. The well (or wells) are operational so long as pressures meet set operating parameters. Over time, the system can be manually optimized or use machine learning to adjust the control points to maximize production while staying within operating constraints of sales line pressure, equipment maximum allowable working pressures, and tank system pressures for air compliance.

Some embodiments optimize well production in a plunger lift scenario by minimizing the risk of loading the well with fluid during a plunger run by ensuring that there is enough pressure to lift the fluid in the tubing, and by maximizing the number of times the well will run. Production can be maximized by maintaining the bottom hole pressures low, thus maximizing differential pressure in the reservoir to the wellbore to have the maximum fluid and gas inflow. A casing pressure is selected that will be able lift the fluid in the tubing to surface, while remaining low enough to maximize fluid and gas inflow to the wellbore. Tubing pressure is selected to be sufficient to overcome sales line pressure and be able to lift the fluid to surface completely.

In other embodiments, manual analysis or machine learning selects a tubing less sales line differential pressure to maximize the number of plunger runs while ensuring enough pressure to not load the well with excessive fluid if the plunger fails to complete the run and reach the surface. The natural buildup of pressure in the well by fluid and gas inflow will occur differently for each well and change over time, so these values need to be analyzed to ensure optimal production. In other words, the selected tubing less sale line pressure value must be low enough to be reached frequently, while high enough to be able to complete the plunger run.

The SpindleIO device waits until the tubing less sale line pressure value is reached, line pressure is below the safety point, and tank system pressures are low enough to absorb the production from the well run. By accounting for tank system pressures, well production will be optimized due to minimal intervention and modulation of production due to high tank system pressures. If there are multiple wells in the tank battery, the next well to run will wait until tank system pressures are below the optimal threshold to allow production to be optimized.

One embodiment of the present invention provides a tank Pressure Control System (PCS) that automatically intervenes and modulates production based on tank system pressures. As separator oil dump events occur, tank pressure will increase. If the production system is retrofitted with the ability to control both the inlet of the separator and the oil dump valve, the SpindleIO system can use an algorithm to allow for continued production past the Upper Control Point, until Trigger Point. If tank pressures increase above the upper control point, the SpindleIO device closes the oil dump valve, thereby preventing additional dump events and allowing vapor pressure in the tank to bleed off to emissions control devices (ECDs). As tank system pressures decrease below the lower control point, the SpindleIO device allows dump events to resume to the tank system. If tank system pressures increase past the trigger point, the inlet valve to the separator will close, discontinuing well production entirely. If the fluid level sensor on the separator increases past the set maximum, the inlet valve to the separator will close, discontinuing well production. If the tank system pressures decrease below the lower control point and the fluid level sensor is below a set level, production will resume by opening the inlet motor valve.

If the production facility is not equipped with the ability to close the oil dump valves, system logic is simpler. As separator oil dump events occur, tank pressure will increase. If tank pressures increase above the upper control point, the SpindleIO device closes the inlet valve to the separator, discontinuing well production entirely. If tank pressure decreases due to the ECDs below the lower control point, production will resume by opening the inlet motor valve. This modulation of production will continue until the production run is over, or if pressures increase above the trigger or leak points of the tank system. If trigger or leak point is exceeded, production will remain shut in until manually resumed by pushing an “On” button on the SpindleIO device, for example. Of course, those of ordinary skill in the art will appreciate that system initiation can be accomplished remotely, for example, by way of a mobile software application.

Accordingly, one object of the present invention discloses a method of optimizing well production through automated pressure monitoring. In this preferred embodiment, the method is initiated by receiving user input data at a mobile computing device, receiving third-party compliance data at a mobile computing device, and creating optimized well-production control data based at least in part on the user input data and the third-party compliance data. The optimized well-production control data is then transmitted to a server via a communication link, and a well production plan is executed at the server based at least in part on the optimized well production control data. In this preferred embodiment, a plurality of pressure sensors collects analog tubing pressure data, analog casing pressure data, analog sales line pressure data, and analog tank pressure data, which are then converted to digital tubing pressure data, digital casing pressure data, digital sales line pressure data and digital tank pressure data, respectively, at the server. The digital tubing pressure data, digital casing pressure data, digital sales line pressure data and digital tank pressure data are then analyzed at the server, wherein the digital tubing pressure data, digital casing pressure data, digital sales line pressure data and digital tank pressure data are compared against each other to create digital differential pressure range data, and wherein the digital differential pressure range data is monitored and maintained at the server for continued well production optimization. In this preferred embodiment, well production output data is created at the server based at least in part on the digital differential pressure range data, which is then transmitted via a wireless or wired communication link to a mobile computing device, wherein the well production output data is analyzed to further optimize well production.

The Summary is neither intended nor should it be construed as being representative of the full extent and scope of the present disclosure. The present disclosure is set forth in various levels of detail in the Summary, as well as in the attached drawings and the Detailed Description, and no limitation as to the scope of the present disclosure is intended by either the inclusion or non-inclusion of elements, components, etc. in this Summary. Additional aspects of the present disclosure will become more readily apparent from the Detailed Description, particularly when taken together with the drawings.

The above-described benefits, embodiments, and/or characterizations are not necessarily complete or exhaustive, and in particular, as to the patentable subject matter disclosed herein. Other benefits, embodiments, and/or characterizations of the present disclosure are possible utilizing, alone or in combination, as set forth above and/or described in the accompanying figures and/or in the description herein below. Further details and other features will become apparent after review of the following Detailed Description and accompanying drawing figures.

BRIEF DESCRIPTION OF THE DRAWINGS

Example embodiments are illustrated in referenced figures of the drawing. It is intended that the embodiments and figures disclosed herein are to be considered illustrative rather than limiting.

FIG. 1 discloses a method of monitoring a plurality of well pressures according to a preferred embodiment.

FIG. 2 discloses a method of optimizing well production output according to a preferred embodiment.

It should be understood that the drawings are not necessarily to scale. In certain instances, details that are not necessary for an understanding of the disclosure or that render other details difficult to perceive may have been omitted. It should be understood, of course, that the disclosure is not necessarily limited to the particular embodiments illustrated herein.

DETAILED DESCRIPTION

The present invention provides its benefits across a broad spectrum of endeavors. It is applicant's intent that this specification and the claims appended hereto be accorded a breadth in keeping with the scope and spirit of the invention being disclosed despite what might appear to be limiting language imposed by the requirements of referring to the specific examples disclosed. Thus, to acquaint persons skilled in the pertinent arts most closely related to the present invention, a preferred embodiment of the system is disclosed for the purpose of illustrating the nature of the invention. The exemplary method of installing, assembling and operating the system is described in detail according to the preferred embodiment, without attempting to describe all of the various forms and modifications in which the invention might be embodied. As such, the embodiments described herein are illustrative, and as will become apparent to those skilled in the art, can be modified in numerous ways within the scope and spirit of the invention, the invention being measured by the appended claims and not by the details of the specification.

Although the following text sets forth a detailed description of numerous different embodiments, it should be understood that the legal scope of the description is defined by the words of the claims set forth at the end of this disclosure. The detailed description is to be construed as exemplary only and does not describe every possible embodiment since describing every possible embodiment would be impractical, if not impossible. Numerous alternative embodiments could be implemented, using either current technology or technology developed after the filing date of this patent, which would still fall within the scope of the claims.

It should also be understood that, unless a term is expressly defined in this patent using the sentence “As used herein, the term ‘______’ is hereby defined to mean . . . ” or a similar sentence, there is no intent to limit the meaning of that term, either expressly or by implication, beyond its plain or ordinary meaning, and such term should not be interpreted to be limited in scope based on any statement made in any section of this patent (other than the language of the claims). To the extent that any term recited in the claims at the end of this patent is referred to in this patent in a manner consistent with a single meaning, that is done for sake of clarity only so as to not confuse the reader, and it is not intended that such claim term by limited, by implication or otherwise, to that single meaning. Finally, unless a claim element is defined by reciting the word “means” and a function without the recital of any structure, it is not intended that the scope of any claim element be interpreted based on the application of 35 U.S.C. § 112, subparagraph (f).

In preferred embodiments, the SpindleIO tank pressure control system addresses new concerns in the oil and gas production industry by modulating and optimizing well production to limit pressure in the storage tank system to ensure compliance with new air regulations and environmental control standards. Pressures from different points in the well and production/tank system are taken into the tank pressure control system through built-in hardware, run through the monitoring and control logic, and valves at the wellhead, inlet to the separator and dump system are controlled by the hardware.

If tank pressures are normal (below thresholds), the controller will act as a normal well controller, turning on the well based on the user's selection of differential pressure, pressure set points or time for a plunger controller, or just time, pressure, or an external pump off controller with a pumping unit.

Based on well performance and tank system design, if pressures start exceeding thresholds where intervention of the system is necessary to modulate well production, the control logic will start “learning” from the operating pressures and begin adjusting the upper and lower control points, and well turn on parameters (depending on user selection of differential pressure, pressure set points or time for a plunger controller, or just time or pressure with a pumping unit) for the optimal production, while maintaining acceptable tank pressures. These settings are range bound by the user to ensure that production operations stay within defined limits.

One embodiment of the present invention discloses a system and method for a monitoring well tank pressures. In this preferred embodiment, multiple tank system pressures are monitored simultaneously for well output optimization. As shown in FIG. 1, the method for monitoring 100 is initiated by monitoring the pressures while the well system is running 102, by uploading operating data every 15 seconds 104 and then determining the twenty-four (24) hour maximum tank pressure 106. Once the 24-hour maximum tank pressure is determined, an assessment is made as to whether the difference between the trigger point and 24-hour average is greater than the adjustment threshold 108. If no, that portion of the tank monitoring has been completed the method returns to monitoring the pressures while the well system is running 102. If, however, the difference between the trigger point and 24-hour average is greater than the adjustment threshold 108, then two additional inquiries are made. The first, is whether the upper control is below the maximum limit 110. If no, then the assessment is made as to whether the well tubing line pressure is below the tubing line pressure maximum line 112. If no, that portion of the tank monitoring has been completed the method returns to monitoring the pressures while the well system is running 102. If, however, the well tubing line pressure is below the tubing line pressure maximum line 112, the well tubing line pressure is adjusted upward by a set adjustment increment 114, the event data is uploaded into the well system monitoring system 116, and that portion of the tank monitoring has been completed, thus returning to monitor the pressures while the well system is running 102. If, the upper control is below the maximum limit 110, then the upper control point is adjusted upward by a predetermined set increment 115, the event data is uploaded into the well system monitoring system 116, and that portion of the tank monitoring has been completed, thus returning to monitor the pressures while the well system is running 102.

The second inquiry that is made after determining that the difference between the trigger point and 24-hour average is greater than the adjustment threshold 108 is whether the trigger point has been exceeded 117 and whether the upper control point is above the upper control point minimum line 118. If yes, then the upper control point is adjusted downward by a set increment 120, the event data is uploaded into the well system monitoring system 122, and that portion of the tank monitoring has been completed, thus returning to monitor the pressures while the well system is running 102. If the trigger point has not been exceeded 117 and the upper control point is not above the upper control point minimum line 118, then the assessment is made as to whether the well tubing line pressure is above the tubing minimum line 124. If no, then the well is shut in 126. If, however, the well tubing line pressure is above the tubing minimum line 124, then the well tubing line pressure is adjusted downward by a set increment 128, the event data is uploaded into the well system monitoring system 122, and that portion of the tank monitoring has been completed, thus returning to monitor the pressures while the well system is running 102.

Simultaneously, while the operating data is uploaded every 15 seconds 104, an assessment is made as to whether the line pressure is above a predetermined normal threshold 132. If yes, the upper control point is adjusted downward over the limit 134, the event data is uploaded into the well system monitoring system 136, and that portion of the tank monitoring has been completed, thus returning to monitor the pressures while the well system is running 102. If the line pressure is below a predetermined normal threshold 137, then the assessment is made as to how, if at all, the upper control point may need to be adjusted downward for a set period of time 138. Subsequently, the event data is uploaded into the well system monitoring system 136, and that portion of the tank monitoring has been completed, thus returning to monitor the pressures while the well system is running 102.

Simultaneously, while the pressures are being monitored while the system is running 102, an assessment is made as to whether the tank pressure is greater than the upper control point 142. If no, then that portion of the tank monitoring has been completed, thus returning to monitor the pressures while the well system is running 102. If, however, the tank pressure is greater than the upper control point 142, the inlet valve is closed 144 and two additional inquiries are made. The first is whether the tank pressure is less than the lower control point 146. If yes, then the that portion of the tank monitoring has been completed, thus returning to monitor the pressures while the well system is running 102. If, however, the tank pressure is greater than the lower control point 146, the assessment of whether the tank pressure is greater than the upper control point 142 is repeated to assess if additional action may be required.

After the inlet valve has been closed 144, the second inquiry that is made is whether the tank pressure is greater than the trigger point 148. If no, then the that portion of the tank monitoring has been completed, thus returning to monitor the pressures while the well system is running 102. If, however, the tank pressure is greater than the trigger point 148, the tank system is shut in and the inlet valve is kept closed 150. Subsequently, the upper control point is adjusted downward with y of the trigger point 152. An additional assessment is also made as to whether the tank pressure is greater than the leak point 154. If no, then the event data is uploaded into the well system monitoring system 156, and the inquiry of whether the tank pressure is greater than the trigger point 148 is repeated to determine subsequent action. If, however, the tank pressure is greater than the leak point 154, the well is shut in 158, the event data is uploaded into the well system monitoring system 160, the tank system issues are manually reviewed and production is resumed 162. Subsequently, the tank monitoring resumes while the well system is running 102.

Referring now to FIG. 2, a preferred embodiment of the present invention discloses a method of optimizing well production through automated pressure monitoring. In this preferred embodiment, the method is initiated by receiving user input data at a mobile computing device 210, receiving third-party compliance data at a mobile computing device 220, and creating optimized well-production control data based at least in part on the user input data and the third-party compliance data 230. The optimized well-production control data is then transmitted to a server via a communication link 240, and a well production plan is executed at the server based at least in part on the optimized well production control data 250. In this preferred embodiment, a plurality of pressure sensors collects analog tubing pressure data, analog casing pressure data, analog sales line pressure data, and analog tank pressure data, which are then converted to digital tubing pressure data, digital casing pressure data, digital sales line pressure data and digital tank pressure data, respectively, at the server 260. The digital tubing pressure data, digital casing pressure data, digital sales line pressure data and digital tank pressure data are then analyzed at the server, wherein the digital tubing pressure data, digital casing pressure data digital sales line pressure data and digital tank pressure data are compared against each other to create digital differential pressure range data, and wherein the digital differential pressure range data is monitored and maintained at the server for continued well production optimization 270. In this preferred embodiment, well production output data is created at the server based at least in part on the digital differential pressure range data 280, which is then transmitted via a wireless or wired communication link to a mobile computing device 290, wherein the well production output data is analyzed to further optimize well production 300.

An example of the method described above with a plunger controller would be the scenario where the initial settings for differential pressure (tubing pressure less line pressure) is 600 PSI, with a range of 400 PSI to 800 PSI and the upper and lower control points for the tank system are 0.575 PSI and 0.45 PSI, respectively with ranges of 0.5125 to 0.6375 and 0.3875 to 0.5125. If the upper control point is exceeded multiple times, the system will begin adjusting the differential pressure for the well lower so that the well will run more frequently and with less production per run. The differential pressure turn on point would decrement by 25 PSI initially to 575 PSI. This should make the dump events less frequent and potentially shorter, allowing the tank system to operate within acceptable pressure limits. This will continue occurring until the differential pressure turn on point is at the minimum value of 400 PSI. If trigger point is exceeded too frequently, the upper control point will be reduced automatically to ensure that exceedances of trigger point are minimized. For example, the upper control point will be initially reduced from 0.575 to 0.565, until it reaches the user defined minimum pressure of 0.5125. If the differential pressure set point is not yet at its minimum, this may further reduce the differential pressure set point through future interventions with pressures exceeding the upper control point.

The opposite of the over pressurization scenario may also occur. If pressures do not exceed a trigger point less a set buffer, the upper control point will be increased to allow the well to run with less potential intervention and modulation. If pressures rarely exceed the upper control point, the differential pressure set point can be adjusted to increase production as defined by user set limits.

After a sufficient data with complete well cycles has been gathered, a machine learning algorithm server-side can be applied to identify trends and determine optimal settings for differential pressure or run time, and upper and lower control points.

Trends can also be analyzed to predict failures within the tank system such as a fouled vent line or small leaks. For example, if the decay rate of tank pressure is unusually high, it may be due to a small leak in the tank system. If the decay rate is unusually low, the vent line or ECD burner tips may be clogged.

All directional references (e.g. top, bottom, front, back) are only used for identification purposes to aid the reader's understanding of the embodiments of the present invention, and do not create limitations, particularly as to the position, orientation, or use of the invention unless specifically set forth in the claims. Joinder references (e.g. attached, coupled, connected, and the like) are to be construed broadly and may include intermediate members between a connection of elements and relative movement between elements. As such, joinder references do not necessarily infer that two elements are directly connected and in fixed relation to each other.

The above-described benefits, embodiments, and/or characterizations are not necessarily complete or exhaustive, and in particular, as to the patentable subject matter disclosed herein. Other benefits, embodiments, and/or characterizations of the present invention are possible utilizing, alone or in combination, as set forth above and/or described in the accompanying figures and/or in the description herein below.

The phrases “at least one,” “one or more,” and “and/or,” as used herein, are open-ended expressions that are both conjunctive and disjunctive in operation. For example, each of the expressions “at least one of A, B and C,” “at least one of A, B, or C,” “one or more of A, B, and C,” “one or more of A, B, or C,” and “A, B, and/or C” means A alone, B alone, C alone, A and B together, A and C together, B and C together, or A, B and C together.

Unless otherwise indicated, all numbers expressing quantities, dimensions, conditions, and so forth used in the specification and drawing figures are to be understood as being approximations which may be modified in all instances as required for a particular application of the novel assembly and method described herein.

The term “a” or “an” entity, as used herein, refers to one or more of that entity. As such, the terms “a” (or “an”), “one or more” and “at least one” can be used interchangeably herein.

The use of “including,” “comprising,” or “having” and variations thereof herein is meant to encompass the items listed thereafter and equivalents thereof as well as additional items. Accordingly, the terms “including,” “comprising,” or “having” and variations thereof can be used interchangeably herein.

It shall be understood that the term “means” as used herein shall be given its broadest possible interpretation in accordance with 35 U. S.C., Section 112(f). Accordingly, a claim incorporating the term “means” shall cover all structures, materials, or acts set forth herein, and all of the equivalents thereof. Further, the structures, materials, or acts and the equivalents thereof shall include all those described in the Summary, Brief Description of the Drawings, Detailed Description and in the appended drawing figures.

In methodologies directly or indirectly set forth herein, various steps and operations are described in one possible order of operation, but those skilled in the art will recognize that steps and operations may be rearranged, replaced, or eliminated without necessarily departing from the spirit and scope of the present invention. It is intended that all matter contained in the above description or shown in the accompanying drawings shall be interpreted as illustrative only and not limiting. Changes in detail or structure may be made without departing from the spirit of the invention as defined in the appended claims. 

What is claimed:
 1. A method of optimizing well production through automated pressure monitoring comprising: receiving user input data at a mobile computing device; receiving third-party compliance data at a mobile computing device; creating optimized well-production control data based at least in part on the user input data and the third-party compliance data; transmitting the optimized well-production control data to a server via a communication link; executing a well-production plan at the server based at least in part on the optimized well-production control data, wherein a plurality of pressure sensors collects two or more of analog tubing pressure data, analog casing pressure data, analog sales line pressure data, and analog tank pressure data; converting the two or more of analog tubing pressure data, analog casing pressure data, analog sales line pressure data, and analog tank pressure data to digital tubing pressure data, digital casing pressure data, digital sales line pressure data and digital tank pressure data, respectively, at the server; analyzing the digital tubing pressure data, digital casing pressure data digital sales line pressure data and digital tank pressure data at the server, wherein the digital tubing pressure data, digital casing pressure data digital sales line pressure data and digital tank pressure data are compared against each other to create digital differential pressure range data, and wherein the digital differential pressure range data is monitored and maintained at the server for continued well production optimization; creating well-production output data at the server based at least in part on the digital differential pressure range data; transmitting the well-production output data via a wireless or wired communication link; and receiving the well-production output data at a mobile computing device, wherein the well-production output data is analyzed to further optimize well production.
 2. The method of claim 1, wherein the well-production output data is stored in a database.
 3. The method of claim 1, wherein the well-production output data comprises alert data if the well production pressure monitoring system reports pre-defined alert conditions.
 4. The method of claim 3, wherein production is shut in when the pre-defined alert conditions exceed one or more pre-defined safety thresholds.
 5. The method of claim 1, wherein the method is used with a wellhead compressor.
 6. The method of claim 1, wherein the method is used with a sales line compressor.
 7. The method of claim 1, wherein the method is used with a pumping unit controller.
 8. The method of claim 1, wherein the method is used with a flowmeter.
 9. The method of claim 1, wherein the well-production output data detects the existence of flowline leaks.
 10. The method of claim 1, wherein the well-production output data detects over pressurization of the discharge.
 11. The method of claim 1, wherein the well-production output data detects the existence of low oil pressure in the compressor.
 12. The method of claim 1, wherein the well-production output data detects the existence of stuffing box over pressurization.
 13. The method of claim 1, wherein the well-production output data regulates the tank pressure.
 14. A method of optimizing well production through automated pressure monitoring comprising: receiving user input data at a mobile computing device; receiving third-party compliance data at a mobile computing device; creating optimized well-production control data based at least in part on the user input data and the third-party compliance data; transmitting the optimized well-production control data to a server via a communication link; executing a well-production plan at the server based at least in part on the optimized well production control data, wherein a plurality of pressure sensors collects analog tubing pressure data, analog casing pressure data, analog sales line pressure data, and analog tank pressure data; converting the analog tubing pressure data, analog casing pressure data, analog sales line pressure data, and analog tank pressure data to digital tubing pressure data, digital casing pressure data, digital sales line pressure data and digital tank pressure data, respectively, at the server; analyzing the digital tubing pressure data, digital casing pressure data digital sales line pressure data and digital tank pressure data at the server, wherein the digital tubing pressure data, digital casing pressure data digital sales line pressure data and digital tank pressure data are compared against each other to create digital differential pressure range data, and wherein the digital differential pressure range data is monitored and maintained at the server for continued well production optimization; creating well-production output data at the server based at least in part on the digital differential pressure range data; transmitting the well-production output data via a wireless or wired communication link; receiving the well-production output data at a mobile computing device, wherein the well production output data is analyzed to further optimize well production.
 15. The method of claim 14, wherein the well-production output data is stored in a database.
 16. The method of claim 14, wherein the well-production output data comprises alert data if the well production pressure monitoring system reports pre-defined alert conditions.
 17. The method of claim 16, wherein production is shut in when the pre-defined alert conditions exceed one or more pre-defined safety thresholds.
 18. The method of claim 14, wherein the well-production output data detects the existence of flowline leaks.
 19. The method of claim 14, wherein the well-production output data detects over pressurization of the discharge.
 20. A method of optimizing well production through automated pressure monitoring comprising: receiving user input data at a mobile computing device; receiving third-party compliance data at a mobile computing device; creating optimized well-production control data based at least in part on the user input data and the third-party compliance data; transmitting the optimized well-production control data to a server via a communication link; executing a well-production plan at the server based at least in part on the optimized well-production control data, wherein a plurality of pressure sensors collect analog tubing pressure data, analog casing pressure data, analog sales line pressure data, and analog tank pressure data; converting the analog tubing pressure data, analog casing pressure data, analog sales line pressure data, and analog tank pressure data to digital tubing pressure data, digital casing pressure data, digital sales line pressure data and digital tank pressure data, respectively, at the server; analyzing the digital tubing pressure data, digital casing pressure data digital sales line pressure data and digital tank pressure data at the server, wherein the digital tubing pressure data, digital casing pressure data digital sales line pressure data and digital tank pressure data are compared against each other to create digital differential pressure range data, and wherein the digital differential pressure range data is monitored and maintained at the server for continued well production optimization; creating well-production output data at the server based at least in part on the digital differential pressure range data; transmitting the well-production output data via a wireless or wired communication link; receiving the well-production output data at a mobile computing device, wherein the well-production output data is analyzed to further optimize well production; and storing the well-production output data in a database. 